Edison Electric Institute Financial Conference November 11 12, 2013 - - PowerPoint PPT Presentation

Edison Electric Institute Financial Conference

November 11 – 12, 2013

1

Cautionary Statements Regarding Forward-Looking Information

This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and

• uncertainties. The factors that could cause actual results to differ materially from the

forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2012 Annual Report on Form 10-K in (a) ITEM

• 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 19; (2) Exelon’s Third Quarter 2013 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18; and (3) other factors discussed in filings with the SEC by the

• Registrants. Readers are cautioned not to place undue reliance on these forward-

looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward- looking statements to reflect events or circumstances after the date of this presentation.

2013 EEI Conference

2

Setting the Context

While we believe in market recovery, we are not waiting for it and are taking actions to improve our value

The current trends in the industry… … are continuing to create a challenging environment… … and Exelon is responding… …while monitoring the power markets for recovery.

• Increasing natural gas production
• Expanding renewable capacity
• Growing demand response and energy efficiency
• Low natural gas and power prices
• Low load growth
• Lack of volatility
• Asset optimization and rationalization
• Leverage business model to identify and invest in growth areas
• Manage costs and improve efficiencies
• Advocate for policies that enable well-functioning competitive markets and

create value for shareholders

• Full impact of coal retirements is not currently reflected in the forward markets
• Significant number of coal plants need additional controls to comply with MATS
• Forward market implied heat rates are trading at a discount to the spot market
• Upside in both forward and spot markets as current heat rates move higher

2013 EEI Conference

3

Exelon’s Strategic Response to the Current Environment

We are biased towards action while we leverage our competencies and strengths to influence

• ur financial future

Asset Optimization Growth Investments Cost Management

Utilities

• Invest $15 billion across the

planning period

• Upgrade aging infrastructure
• Invest in infrastructure and new

technologies

• Provide stable earnings growth

ExGen

• Invest in renewables and

expand footprint in the natural gas business to diversify

• Maintain retail pricing discipline
• Bolster presence in core regions
• Research and invest in

emerging technologies Review Solutions from All Angles

• Infrastructure
• Commercial
• Policy
• Legal

Scenarios for Optimization

• Cost and productivity

enhancement

• Operations improvement
• Transmission
• PPAs
• Sale
• Retirement

Our Record

• Record of managing costs
• $550 million in merger

synergies

• Reduced 2013 ExGen O&M by

$150 million

• CENG annual projected

synergies of $50-70 million(1)

Continued Focus

• Expand cost management

efforts

• Efficiency gains through

productivity and technology enhancements

• Share best practices across the

utilities

(1) At 100% ownership, Exelon share is 50% 2013 EEI Conference

4

Advocating for Public Policy to Enhance Customer and Shareholder Value

PJM:

• Engaged in stakeholder process

regarding PJM reliance on planned resources

• Minimum Offer Price Rule

(MOPR) Reform

• Demand Response Reforms

ERCOT:

• Resource adequacy

New England:

• Energy and capacity market

reforms RGGI:

• New Model Rule

Oppose Subsidized Generation:

• IL: Defeated Taylorsville Energy

Project Subsidy legislation

• MA: Opposed Footprint Power

Subsidy legislation

• NJ: Won LCAPP Court decision

Infrastructure & Ratemaking Improvements:

• IL: Energy Infrastructure and

Modernization Legislation (Senate Bill 9)

• MD/PA: Policies to speed

recovery for gas and infrastructure investments Market Policy Federal Policy State Policy

Regulatory / Policy Actions

Subsidies:

• Leading voice against extension
• f the Production Tax Credit and
• ther electric generation

subsidies EPA Regulations:

• Mercury and Air Toxics

Standards (MATS)

• Greenhouse gases (new and

existing sources)

• 316(b)

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5

Investing in a Stronger Future

Utili lity ty Investm stmen ent Oper eratin ating Excelle ellence Asset t Optimization ization Portf tfoli

• lio
• Managem

agement Strong

• ng Balanc

ance e Sheet et Significant infrastructure and technology enhancements under regulatory structures that allow a fair rate of return. Generating fleet will continue unwavering focus on world class performance. Disciplined fleet evaluation will drive strategic decisions to unlock value, improve cash flow and grow earnings. Enhance the value of our portfolio through implementation of our fundamental view and disciplined retail pricing. Solid financial footing and investment grade credit rating will allow us to grow in challenging times. Core Strength Strategic Focus and Actions Well-Crafted ed Public ic Policie ies Advocate for policies that strengthen competitive markets, limit subsidies and enhance the value of clean generation.

2013 EEI Conference

Financial Update

7

2013 Operating Earnings Guidance

2013 Prior Guidance

(prior to 3Q earnings call)

$2.35 - $2.65(1)

$1.40 - $1.60 $0.35 - $0.45 $0.35 - $0.45 $0.15 - $0.25

ExGen ComEd PECO BGE

(1) Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to slide 15 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating EPS.

Key Drivers of Change in Full-Year Guidance

• Strong YTD earnings

through Q3

• Lower than expected

ExGen gross margin largely offset by O&M savings

• Delay of AVSR project
• Lower storm costs at

utilities

2013 EEI Conference

2013 Revised Guidance

(disclosed at 3Q earnings call)

$2.40 - $2.60(1)

$1.40 - $1.50 $0.45 - $0.50 $0.40 - $0.45 $0.20 - $0.25

ExGen ComEd PECO BGE

Capital Expenditure Expectations

75 100 100 25 50 25 125 100 75 50 25 50 25 75 150 2,075 750 1,050 100 2015 2,350 875 950 200 2014 2,400 900 900 150 2016 2013 2,725 950 1,000 25 500 150 Base Capex Nuclear Fuel Fukushima Response(2) MD Commitments Wind Solar Upstream Gas Nuclear Uprates 1,400 575 200 450 1,725 850 225 300 2014 3,025 1,650 700 225 450 2013 2,625 2016 2,950 1,750 725 250 225 2015 3,100 Electric Distribution Electric Transmission Gas Delivery Smart Grid/Smart Meter

Exelon n Utiliti ties Exelon n Generati tion(1)

(1)

(in $M) (in $M)

8 2013 EEI Conference (1) Excludes CENG (2) Fukushima Response spend excludes Salem, which is included in Base CapEx

2013 Projected Sources and Uses of Cash

9 2013 EEI Conference

($ in millions) BGE ComEd PECO ExGen Exelon( 6) As of 2Q13 Delta Beginning Cash Balance ( 1) 1,575 1,575

• Cash Flow from Operations(2)

575 1,075 650 3,550 5,775 5,550 225 CapEx (excluding other items below): (500) (1,300) (375) (1,000) (3,275) (3,300) 25 Nuclear Fuel n/a n/a n/a (1,000) (1,000) (1,000)

• Dividend(3)

(1,250) (1,250)

• Nuclear Uprates

n/a n/a n/a (150) (150) (150)

• Wind

n/a n/a n/a (25) (25) (25)

• Solar

n/a n/a n/a (500) (500) (550) 50 Upstream n/a n/a n/a (50) (50) (50)

• Utility Smart Grid/Smart Meter

(125) (150) (175) n/a (450) (450)

• Net Financing (excluding

Dividend): Debt Issuances 300 350 550

• 1,200

1,200

• Debt Retirements(4)

(400) (250) (500) (450) (1,600) (1,600)

• Project Finance/Federal Financing

Bank Loan n/a n/a n/a 850 850 1,025 (175)

• Other(5)

75 350 (75) (125) 325 300 25 Ending Cash Balance ( 1) 1,425 1,275 150 150 (1) Exelon beginning cash balance as of 1/1/13. Excludes counterparty collateral activity. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures. (3) Dividends are subject to declaration by the Board of Directors. (4) Includes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo and excludes BGE’s current portion of its rate stabilization bonds (5) “Other” includes proceeds from options, redemption of PECO preferred stock and expected changes in short-term debt, including money pool activity. (6) Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

Commitment to Investment Grade

Value of Investment Grade

• Maintain key credit metrics above target ranges under both market and

stress conditions to maintain investment grade ratings

• Shareholder value of maintaining investment grade:

− Increases ability to participate in commercial business opportunities − Lowers collateral requirements − Reliable and cost efficient access to the capital markets − Increases business and financial flexibility

Current Ratings & Targets

Moody’s S&P Fitch Corp Baa2 BBB- BBB+ ComEd A3 A- BBB+ PECO A1 A- A BGE Baa1 A- BBB+ Generation Baa1 BBB BBB+

Current Ratings (1) (2) Credit Metric Targets Supportive of Mid-High BBB/Baa Ratings (3)

• FFO/Debt > 30% in base case and

27% in stress case

• RCF/Debt > 20%
• Positive Moody’s FCF

Exelon remains committed to maintaining investment grade ratings

(1) Current senior unsecured ratings for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO as of September 25, 2013. (2) All ratings at S&P and Moody’s have a stable outlook. On August 23rd, BGE was upgraded one notch to A- as part of S&P’s annual

• review. All other entities were affirmed. Additionally, on February 8th, Fitch affirmed all ratings for Exelon and subs and placed

ComEd on positive outlook. (3) Credit metric target ranges are for ExGen and include the debt obligations of Exelon Corp.

10 2013 EEI Conference

Pension and OPEB Forecast

Current Forecast:

• The table below provides the combined company’s forecasted 2014 and 2015 pension and OPEB expense

and contributions

11 2013 EEI Conference

2014 2015 (in $M)

Pre-Tax Expense(1) Contributions(2) Pre-Tax Expense(1) Contributions(2)

Pension(3)(4) $335 $275 $315 $175 OPEB(3)(4) $165 $210 $160 $200 Total $500 $485 $475 $375

(1) Pension and OPEB expenses assume an ~ 25% capitalization rate. (2) Contributions shown in the table above are based on the current contribution policy for the plans and include both amounts contributed to trusts and paid from corporate assets. (3) Expected return on assets for pension is 7.00% and for OPEB is 6.45% (2014 and 2015). Amounts above assume an actual return on assets for pension and OPEB in 2013 of 4.88% and 8.00%, respectively. (4) Projected 12/31/13 pension and OPEB discount rates are 4.80% and 4.92%, respectively.

2014 Pension and OPEB Sensitivities

12 2013 EEI Conference

• Tables below provide sensitivities for the combined company’s 2014 pension and OPEB expense and

contributions(1) under various discount rate and S&P 500 asset return scenarios

(1) Contributions shown in the table above are based on the current contribution policy and include the impact of pension funding relief. (2) Pension and OPEB expenses assume an ~ 25% capitalization rate in 2014. (3) Final 2013 asset return for pension and OPEB will depend in part on overall equity market returns for Q4 2013 as proxied by the S&P 500. The amounts above reflect YTD S&P returns through September 30, 2013. (4) The baseline discount rates reflect projected 12/31/13 pension and OPEB discount rates of 4.80% and 4.92%, respectively.

2014 Pension Sensitivity(2) (in $M)

S&P Returns in Q4 2013(3) 10% 0%

• 10%

Discount Rate at 12/31/13

Pre-Tax Expense(1) Contributions(2) Pre-Tax Expense(1) Contributions(2) Pre-Tax Expense(1) Contributions(2)

Baseline Discount Rate(4) $325 $275 $335 $275 $350 $275 +50 bps $295 $25 $300 $275 $315 $275

• 50bps

$365 $275 $380 $275 $390 $275

2014 OPEB Sensitivity(2) (in $M)

S&P Returns in Q4 2013(3) 10% 0%

• 10%

Discount Rate at 12/31/13

Pre-Tax Expense(1) Contributions(2) Pre-Tax Expense(1) Contributions(2) Pre-Tax Expense(1) Contributions(2)

Baseline Discount Rate(4) $155 $195 $165 $210 $180 $225 +50 bps $135 $180 $150 $185 $160 $200

• 50bps

$180 $220 $190 $235 $200 $250

13

Additional 2013 ExGen and CENG Modeling

P&L Item 2013 13 Estima mate

ExGen n Model Inp nputs uts

(1) (1)

O&M

(2)

$4,275M Taxes Other Than Income (TOTI)

(3)

$300M Depreciation & Amortization(4) $825M Interest Expense $350M CENG Model Inp nputs uts (at ownersh ship) p) (5)

(5)

Gross Margin Included in ExGen Disclosures O&M/TOTI $400M - $450M Depreciation & Amortization/Accretion of Asset Retirement Obligations $100M - $150M Capital Expenditures $75M - $125M Nuclear Fuel Capital Expenditure $100M - $150M

(1) ExGen amounts for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of unconsolidated affiliates” in the Income Statement. (2) ExGen O&M excludes P&L neutral decommissioning costs and the impact from O&M related to entities consolidated solely as a result of the application of FIN 46R. (3) TOTI excludes gross receipts tax for retail. (4) ExGen Depreciation & Amortization excludes the impact of P&L neutral decommissioning. (5) The CENG model inputs are intended to support Exelon’s guidance range and do not represent CENG’s final estimates. 2013 EEI Conference

Debt Maturity Schedule

(in $M)

Debt Maturity Profile(1) (2014-2020)

14 2013 EEI Conference (1) As of 9/30/13 (2) Includes $550M in 2015 and 2020 of inter-company loan agreements between Exelon and Exelon Generation that mirror the terms and amounts of the third party

• bligations of Exelon.

500 840 2017 2020 1,600 1,100 1,340 2019 2018 600 500 1,125 700 425 2016 1,342 77 300 665 300 2015 1,610 550 260 800 2014 1,482 615 250 617

Exelon Corp BGE ExGen (2) PECO ComEd

GAAP to Operating Adjustments

15 2013 EEI Conference

• Exelon’s 2013 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

− Mark-to-market adjustments from economic hedging activities − Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements − Financial impacts associated with the sale or retirement of generating stations − Financial impacts associated with the increase in certain decommissioning obligations for spent nuclear fuel at retired nuclear units and increased retirement obligations for retired fossil power plants − Certain costs incurred associated with the Constellation merger and integration initiatives − Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date − Non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013 − Non-cash charge to earnings resulting from the remeasurement of Exelon’s like-kind exchange tax position − Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects and the impairment of certain wind generating assets − Other unusual items

Exelon Utilities

17

ComEd April 2013 Distribution Formula Rate Updated Filing

Docket # 13-0318 Filing ing Year 2012 Calend ndar ar Year Actual al Costs and 2013 Projected Net Plant Additio ions ns are used to set the rates for calendar year 2014. Rates currently in effect (docket 13-0386) for calendar year 2013 were based on 2011 actual costs and 2012 projected net plant additions and reflect the impacts of PA 98-0015 (SB9). Reconc ncilia iliatio ion n Year Reconc ncile iles Revenue e Requirement ent reflected in rates during ing 2012 to 2012 Actual al Costs Incur urred.

• ed. Revenue requirement for

2012 is based on dockets 10-0467, 11-0721 May Order and 11-0721 October Re-hearing Order. Common n Equity Ratio io ~ 45% for both the filing and reconciliation year ROE 8.72% % for both the filing and reconciliation year (2012 30-yr Treasury Yield of 2.92% + 580 basis point risk premium). For 2013 and 2014, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread. Requested ed Rate of Return ~ 7% for the both the filing and reconciliation year Rate Base $6,702 millio lion– Filing year (represents projected year-end rate base using 2012 actual plus 2013 projected capital additions). 2013 and 2014 earnings will reflect 2013 and 2014 year-end rate base respectively. $6,389 millio lion n - Reconciliation year (represents year-end ate base for 2012) Revenue ue Requirement ent Increas ase (1) $353M ($191M is due to the 2012 reconciliation, $162M relates to the filing year). The 2012 reconciliation impact on net income was recorded in 2012 as a regulatory asset. This increase also reflects the decrease in 2013 rates as a result of Senate Bill 9. Timeli line ne

• 04/29/13 Filing Date
• 240 Day Proceeding
• ICC order by year end; rates effective January 2014

The 2013 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the ICC’s review. The filing was updated to reflect the impact of Senate Bill 9. There are two components to the annual distribution formula rate filing:

• Filing Year: Based on prior year costs (2012) and current year (2013) projected plant additions.
• Annual Reconciliation: For the prior calendar year (2012), this amount reconciles the revenue requirement reflected in rates during the prior year

(2012) in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2014) but the earnings impact has been recorded in the prior year (2012) as a regulatory asset.

Given en the ret etroa

• activ

ive e ratema emakin ing provi vision sion in the EIMA A legisla slatio ion, , ComEd Ed net et income

• me during the year will

l be based sed on actual al cost sts s with a regulat lator

• ry asset/liab

/liabili ility recorde ded d to reflec lect any under/o /over recovery reflec lected ed in rates.

• es. Revenue

e Requir quiremen ment in rate e filings s impa mpacts s cash h flow.

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BGE Rate Case

2013 EEI Conference

Rate e Case e Reques quest Electri ctric Gas

Docket # 9326 Test Year August 2012 – July 2013 Common Equity Ratio 51.1% Requested Returns ROE: 10.5%; ROR: 7.87% ROE: 10.35%; ROR: 7.79% Rate Base $2.8B $1.0B Revenue Requirement Increase $82.6M $24.4M Proposed Distribution Price Increase as % of overall bill 2% 3%

Timelin eline

• 5/17/13: BGE filed application with the MDPSC seeking increases in gas & electric distribution base rates
• 8/5/13: Staff/Intervenors file direct testimony
• 8/23/13: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(March - July 2013)

• 9/17/13: BGE and staff/intervenors file rebuttal testimony
• 10/3/13: Staff/Intervenors and BGE file surrebuttal testimony
• 10/18/13 – 10/29/13: Hearings
• 11/12/13: Initial Briefs
• 11/22/13: Reply Briefs
• 12/13/13: Final Order
• New rates are in effect shortly after the final order

19

ComEd Load

2013 EEI Conference

Weather-Normalized Load YoY Growth Economic Forecast of Drivers that Influence Load 2013E

0.1%

• 0.6%
• 0.5%
• 0.3%

1.2%

2012

• 0.3%

0.2%

• 0.6%
• 0.1%

2.1% GMP Large C&I Small C&I Residential All Customers Driv iver er or Indic icat ator

• r

2014 Outlook

• k

Gross Metro Product (GMP)

2.2% growth in GMP reflects overall better economic conditions than the slow growth in 2013 (Manufacturing and Professional Business Services employment accelerate in 2014)

Employment

1.4% increase in total employment is expected for 2014, which is consistent with the past three years

Manufacturing

Manufacturing employment is expected to grow 1.4% in 2014. This is a significant improvement

• ver the 0.7% growth in 2012 and the 0.4%

growth in 2013

Households

Household formations are expected to increase 0.4% in 2014. This is a slight improvement over the 0.3% realized in the past couple of years

Energy Efficiency

Continued expansion of EE program expected to reduce usage in 2014 by approximately 1.2%

Notes: 2012 data is not adjusted for leap year. Source of 2014 economic outlook data is Global Insight (July 2013).

Moderate growth economy and energy efficiency initiatives will continue to impact load growth

20

PECO Load

Weather-Normalized Load YoY Growth Economic Forecast of Drivers that Influence Load 2013E

• 2.4%

1.7%

• 0.2%

0.2% 1.0%

2012

• 2.7%
• 2.3%
• 1.7%
• 2.2%

1.5% GMP Large C&I Small C&I Residential All Customers Driv iver er or Indicat ator

• r

2014 Outlook

• k

Gross Metro Product (GMP) GMP projected to grow at 2.1% for 2014,

• vs. pre-recession average of 2.5%

Resident Employment Resident Employment outlook is 1.0% in 2014 vs. 0.8% in 2013 Manufacturing Employment Manufacturing employment is expected to grow at 1.1%. Philadelphia has had negative growth from 2000 to 2013 Households Household growth is expected to be 0.7%, strongest growth since 2010 Energy Efficiency Deemed Energy Efficiency impact forecasted to be ~1% reduction in usage in 2014

Moderately strong economic recovery will drive sales in 2014, but this will be partially offset by on-going energy efficiency initiatives

2013 EEI Conference Notes: 2012 data is not adjusted for leap year. Source of 2013 economic outlook data is Global Insight (August 2013)

21

BGE Load

Weather-Normalized Load YoY Growth Economic Forecast of Drivers that Influence Load 2013E

• 3.6%

1.4%

• 1.1%

1.8%

2012

• 0.2%
• 2.8%
• 2.1%
• 1.5%

GMP Large C&I Small C&I Residential All Customers Driv iver er or Indicat ator

• r

2014 Outlook

• k

Gross Metro Product (GMP) GMP is projected to grow at 2.4% for 2014. Employment 1.4% growth projected. BGE’s decoupled non-rate case revenue growth is primarily driven by customer growth. The main driver for customer growth is employment. Manufacturing Manufacturing employment is expected to be fairly flat to 2013 levels in 2014 Households Household growth is projected to be 0.9%, the same as 2013. Energy Efficiency Continued expansion of EE programs will partially offset growth seen due to improvements in economic conditions.

2014 is expected to be another transition year for the Baltimore economy with continued slow to moderate growth

Notes: 2012 Data is not adjusted for leap year. Source of 2014 economic outlook data is Global Insight (August 2013).

1.4% 2.5%

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22

Exelon Utilities: Rate Base(1) and ROE Targets

2013E Long-Term Target

Equity Ratio ~49% ~53%(4) Earned ROE 8.0-8.5%

2013E Long-Term Target

Equity Ratio ~45% ~53%(2) Earned ROE 8 -9%

Continued investment in Utilities will provide stable earnings growth

Based on 30-yr. US Treasury(3) ($ in billions) 2013E $5.4 $3.5 $0.7 $1.1 $1.3 2016E $4.0 $0.8 $6.1 2015E $5.9 $3.9 $0.7 $1.3 2014E $5.7 $3.8 $0.7 $1.2 Electric Distribution Electric Transmission Gas Delivery 2014E $9.5 $7.2 $2.3 2013E $8.7 $6.6 $2.1 2016E 2015E $10.7 $7.9 $2.9 $11.6 $3.1 $8.5 Distribution Transmission $3.1 $5.1 $3.0 $0.8 $1.2 2014E $4.8 $3.0 $0.7 $1.2 2013E $4.6 $2.9 $0.6 $1.1 $0.9 2016E $5.3 $1.3 2015E Electric Distribution Electric Transmission Gas Delivery

≥10%

(1) ComEd and PECO rate base represents end-of-year; and BGE rate base represents a trailing 13-month average. Numbers may not add due to rounding. (2) Equity component for distribution rates will be the actual capital structure adjusted for goodwill. (3) Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE and distribution ROE resulting from 30-year Treasury plus 580 basis points for each calendar year. 2013 EEI Conference (4) Per MDPSC merger commitment, BGE is precluded from paying dividends through 2014. Per MDPSC orders, BGE cannot pay out a dividend to its parent company if said dividend would cause BGE’s equity ratio to fall below 48%.

2013E

Long-Term Target

Equity Ratio ~56% ~53% Earned ROE

11.5 – 12.5%

≥10%

23

Capital Expenditures

($ in millions) $275 $25 $75 $100 2014E $625 $300 $175 $50 $100 2013E $550 2016E $425 $250 $75 $100 2015E $475 $225 $175 $50 $100 Electric Distribution Smart Meter/Smart Grid(1) Electric Transmission Gas Delivery 2015E $2,025 $1,150 $275 $600 2014E $1,775 $1,050 $175 $550 2013E $1,450 $850 $150 $450 2016E $1,925 $225 $500 $1,200 2015E $600 $300 $175 $125 2014E $625 $150 $150 $300 $300 $100 $100 $125 2013E $625 $300 $100 $100 $125 2016E $600

(1) Smart Meter/Smart Grid CapEx net of proceeds from U.S. Department of Energy (DOE) grant. For BGE, includes CapEx from Smart Energy Savers program of ~$10M per year. 2013 EEI Conference

24

Regulatory Schedule

4Q13 1Q14 2Q14 3Q14

2014 formula rate case filing (by 5/15/14)

ComEd Distribution Formula Rate Illinois Power Agency Procurement ComEd Transmission Rate Update

2014 formula rate case filing (by 5/15/14); rates effective June 2014 thru May 2015 2014 formula rate case filing final order (by 12/31/14); rates effective 1/2/15 – 12/31/15

4Q14

BGE Distribution Rates PECO Supply Procurement BGE Transmission Rate Update

2014 formula rate case filing (by 5/15/14); rates effective June 2014 thru May 2015 MDPSC Order expected December 13, 2013

BGE Supply Procurement

Regular procurement event (January) Regular procurement event (April and June) Potential Electric and Gas DSIC Filing

PECO Distribution Filing

13-0318 final order (by 12/25); rates effective 1/2/14 – 12/31/14 DSP II Procurement (January) DSP II Procurement (September) Regular procurement event (October) Regular procurement event (October) IPA proposed procurement events in April and September

2013 EEI Conference

26

Commercial Business Overview

Upstream Exploration & Production Power Generation Electric, Gas Retail & Wholesale Beyond The Meter Scale, Scope and Flexibility Across the Energy Value Chain

Development and exploration of natural gas and liquids properties 12 assets in seven states ~255 BCFe of proved Reserves(1) Leading merchant power generation portfolio in the U.S. ~35 GW of owned generation capacity(2) Clean portfolio, well positioned for evolving regulatory requirements Industry-leading wholesale and retail sales and marketing platform ~150 TWh of load and ~410 BCF of gas delivered(3) ~ 1 million residential and 100,000 business and public sector customers One of the largest and most experienced Energy Management providers ~2,000 MW of Load Response under contract(4) Over 4,000 energy savings projects implemented across the U.S.

Benefiting from scale, scope and flexibility across the value chain

(1) Estimated proved reserves as of 12/31/2012. Includes Natural Gas (NG), NG Liquids (NGL) and Oil. NGL and Oil are converted to BCFe at a ratio of 6:1. (2) Total owned generation capacity as of 9/30/2013. (3) Expected for 2013 as of 9/30/2013. Electric load and gas includes fixed price and indexed products. (4) Load Response estimate as of 9/30/2013. 2013 EEI Conference

8 12 12 5 13 13 15 15 15 15 16 16 18 18 47 47 74 74 22 22 97 97 South/West/ Canada 24 24 New York 14 14 New England 31 31 ERCOT 42 42 MidAtlantic 114 114 MidWest 111 111

27

Generation and Load Match

The combination establishes an industry-leading platform with regional diversification of the generation fleet and customer-facing load business

Generation Capacity, Expected Generation and Expected Load

2014 in TWh (1,2)

(1) Owned and contracted generation capacity converted from MW to MWh assuming 100% capacity factor for all technology types, except for renewable capacity which is shown at estimated capacity factor. (2) Expected generation and load shown in the chart above will not tie out with load volume and ExGen disclosures. Load shown above does not include indexed products and generation reflects a net owned and contracted position. Estimates as of 9/30/2013.

Expected Load Expected Generation

Generation capacity:

2013 EEI Conference

Peaking Intermediate Baseload Renewables

28

Electric Load Serving Business: Growth Target

20 40 60 80 100 120 140 160 2016E 155 155

75-85% 15-25%

2015E 155 155

65-75% 25-35%

2014E 155 155

60-70% 30-40%

2013E 150 150

60-70% 30-40%

Retail Load(2) Wholesale Load Total Contracted

Commercial Load (1)

2013 – 2016 TWh

8% 15% Load Split by Customer Class

(2013 TWh)

Focus on disciplined pricing and maximizing margin potential through all channels to market A diverse set of customers enhances margin opportunities from a sales and portfolio management standpoint

(1) Numbers and percentages are rounded to the nearest 5 (2) Index load expected to be 20% to 30% of total forecasted retail load

Customer er Type Load Size Mass Markets <1,000 MWhs per year Small C&I 1,001-5,000 MWhs per year Medium C&I 5,001-25,000 MWhs per year Large C&I >25,000 MWhs per year

33% Large C&I Mass Markets Small C&I 7% Medium C&I 16% 8% 35% Wholesale

C&I = Commercial & Industrial 2013 EEI Conference

29

Electric Load Serving Business: Strategy

Constellation is well positioned in a U.S. market where capacity available for competitive supply has room to grow

Total U.S. Power Market in 2013 Estimated Load ~ 3,700 TWh (1) 30% 15%

35% 19% 45% 18%

(1) Source: EIA, KEMA and internal estimates.

Through retail and wholesale channels, Constellation currently serves 150 TWhs, or approximately 4%, of total U.S. power demand

18% Eligible Non-Switched 14% Eligible Switched 20% Muni/Co-Op Market Other Ineligible 48%

Expect cted ed Tot

• tal Comp

mpetitiv etitive e Mark rket et Growth

• Underlying load growth

− Approx. 1% load growth across the U.S.

• Switched market expected to grow by approximately 5%

in C&I from 2013-2016

• Switched market expected to grow by approximately 3%

in Residential from 2013-2016 Stra rateg egy y to Grow

• Improve market share in existing markets
• Cross sell suite of products to existing customers

― Create more value with customers ― Utilize data and technology to expand product offerings ― Achieve higher renewal rates ― Distinguish our brand

• Leverage operational efficiency

2013 EEI Conference

Capacity Markets

30

2012/ 2013 2013/ 2014 2014/ 2015 2015/ 2016 2016/ 2017 PJM(3,8) RTO Capacity 12,800 11,500 11,500 11,500 11,250 Price $16 $28 $126 $136 $59 EMAAC Capacity(4) 9,100 9,100 9,100 9,100 9,100 Price $140 $245 $137 $168 $119 MAAC Capacity 2,600 2,700 2,700 2,700 2,700 Price $133 $226 $137 $168 $119 SWMAAC Capacity(5) 1,800 1,800 1,800 1,800 1,800 Price $133 $226 $137 $168 $119 Average Exelon $78 $142 $132 $153 $92 New England(6) NEMA Capacity 2,100 2,100 2,100 2,100 2,100 Price $85(7) $85(7) $107 $114 $219 Rest of Pool Capacity 735 735 735 735 735 Price $85(7) $85(7) $95(7) $104(7) $90 NYISO(8) Rest of Pool Capacity 1,100 1,100 1,100 1,100 1,100 MISO(9) AMIL Capacity 1,100 1,100 1,100 1,100 1,100

RTO = Regional Transmission Organization, MAAC = Mid-Atlantic Area Council, EMAAC = Eastern Mid-Atlantic Area Council, SWMAAC = South West Mid-Atlantic Area Council, NEMA = North East Massachusetts; SEMA = North East Massachusetts, AMIL = Ameren Illinois. (1) Revenues reflect capacity cleared in base and incremental auctions and are for calendar years. Revenue rounded to nearest $50M. (2) Weighted average $/MW-Day would apply if all owned generation cleared. (3) Reflects owned and contracted generation Installed Capacity (ICAP) adjusted for mid-year PPA roll offs. (4) ICAP is net of Eddystone 1&2, Cromby 1&2 and Schuykill 1 (total ~ 1,100 MW). (5) ICAP is net of units to be divested (Brandon Shores, Wagner & Crane ~2,648 MW; Constellation

• ffered these units in PY11/12 - PY 15/16 auctions) and Riverside 6 CT (~115MW).

(6) Reflects Qualified Summer Capacity including owned and contracted units. (7) Price is pro-rated for auctions that clear at the floor price and there is more capacity procured than suggested by the reliability requirement. (8) Reflects 50.01% ownership in CENG. (9) Does not include wind under PPA. 2013 EEI Conference

$0 $50 $100 $150 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 $1,100 $1,200 $1,300 2016 2015 2014 Revenue ue ($MM) 2013 Capac acity Price ($/MWd Wd) $116 $136 $144 $117

PJM RPM Capacity Revenues(1)

Exelon Fleet Weighted Price ($/MWd) Revenue ($MM)

(2)

31

Retail and Wholesale Gas

(1) Estimate as of 9/30/2013.

Retail Gas Portf tfoli

• lio
• Size:

e:

• 410 Bcf expected to be served in 2013 with

moderate growth thereafter

• Month by month renewals, with high retention

rates Market t Pot

• tentia

ial: l:

• All states are competitive markets with an

estimated total market size of 15,000 Bcf, of which 7,500 Bcf is currently switched Growth h Strat ateg egy and Objec ectiv tives: s:

• Looking to grow Northeast gas markets as well

as ONEOK territories Wholesale Gas Portf tfoli

• lio
• Size:

e:

• 8 Bcf wholesale storage
• 450,000 MMBtu’s per day of term transport
• Over 1 Bcf/day of plant supply
• ~4Bcf/day of NG flows to meet growing

customer business, asset optimization, and plant supply Growth h Strat ateg egy and Objec ectiv tives:

• Continue to expand wholesale presence to

complement power assets

• Increase market knowledge of regional and

basis transport information to assist power forecasting

• Continue to expand physically based customer

business

• Continue to grow NG asset portfolio that

complements customer business & plant supply requirements

2013 EEI Conference

32

(1) Oil/NGL conversion to gas is 6:1. (2) Constellation does not operate any of its properties. Note: E&P = Exploration and Production (3) 12/31/12 Year end reserves excluding Eagle Ford (4) Net daily production as of Q2 2013 excluding Eagle Ford

Upstream E&P Assets

Estimated ed Net Proved ved Reserves es (as of 12/31/12)3 Average verage Net Daily ly Product uction ion (Q2 2013)4 255 Bcfe 61.0 MMcfe Investment Thesis

• Our Upstream Gas business achieves strong returns

(>12% IRR)

• $125m (~62% utilized) Reserve Based Lending (RBL)

facility in place ― Receives off-balance sheet treatment from S&P

• Provides valuable market intelligence in complex

natural gas markets Foreca ecasted ed Production ion 2013 2014 2015 2016 Net Daily Prod (MMcfe / day) 55 - 70 45 - 60 45 - 60 60 - 75 Current Portfolio Of Investments Mississippi lime (OK) Hunton dewatering (OK) Woodford shale (OK) Fayetteville shale (AR) Haynesville shale (LA) Floyd shale (AL) Ohio shale (OH) Woodbine shale (TX) Trenton Black River (MI) Barnett shale (TX)

2013 EEI Conference

2013 EEI Conference 33

Energy Price Upside - NIHub

We continue to believe there is $4 of upside in NiHub energy prices in 2015/2016 driven by several factors including compliance with environmental regulations

• The charts above illustrates NIHub prices from 2011 to 2016 (realized through 2013) and NYMEX natural

gas for the same time period

• In 2012 we saw low prices in the natural gas and power markets.

― Natural gas prices settled $2.75 for the year and NIHub ATC prices settled ~$29.00. The forward market for NIHub continues to trade between $30.50 and $31.00 even though forward natural gas prices are between $1.00 - $1.50 per MMBtu higher than the spot levels we saw in 2012.

$31.00 $30.50 $31.25 $33.07 $4.21 $4.10 $3.91 2011 2012 2013 2014 2015 2016 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $36.00 $34.00 $32.00 $30.00 $28.00 $26.00 $24.00 $30.25 $3.68 $2.75 $28.95 $3.99 $/ $/MMBtu $/ $/MWh

Realized Forward

Key Drivers

• Year over year increases in fuel prices
• Current and future coal retirements
• Higher variable unit costs due to MATS
• Modest load growth
• Offset by new generation (gas and renewable)

Other factors (not included)

• Demand Response energy bidding
• Increased variable costs due to RGGI
• Scarcity pricing

NG-NYMEX NIHub Upside NIHub ATC

34

Exelon Generation Disclosures

September 30, 2013 (As disclosed in Third Quarter 2013 Earnings materials)

2013 EEI Conference

35

Portfolio Management Strategy

Protect Balance Sheet Ensure Earnings Stability Create Value

Strategic Policy Alignment

• Aligns hedging program with financial

policies and financial outlook

• Establish minimum hedge targets to

meet financial objectives of the company (dividend, investment-grade credit rating)

• Hedge enough commodity risk to meet

future cash requirements under a stress scenario Three-Year Ratable Hedging

• Ensure stability in near-term cash

flows and earnings

• Disciplined approach to hedging
• Tenor aligns with customer

preferences and market liquidity

• Multiple channels to market that

allow us to maximize margins

• Large open position in outer years

to benefit from price upside

Bull / Bear Program

• Ability to exercise fundamental market

views to create value within the ratable framework

• Modified timing of hedges versus

purely ratable

• Cross-commodity hedging (heat rate

positions, options, etc.)

• Delivery locations, regional and zonal

spread relationships

Exercising Market Views

% Hedged

Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization

Portfolio Management Over Time Align Hedging & Financials Establishing Minimum Hedge Targets

Credit Rating Capital & Operating Expenditure Dividend Capital Structure

2013 EEI Conference

36

Components of Gross Margin Categories

Open Gross Margin

• Generation Gross

Margin at current market prices, including capacity & ancillary revenues, nuclear fuel amortization and fossils fuels expense

• Exploration and

Production

• PPA Costs &

Revenues

• Provided at a

consolidated level for all regions (includes hedged gross margin for South, West & Canada(1))

MtM of Hedges(2)

• MtM of power,

capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions

• Provided directly at

a consolidated level for five major

• regions. Provided

indirectly for each

• f the five major

regions via EREP, reference price, hedge %, expected generation

“Power” New Business

• Retail, Wholesale

planned electric sales

• Portfolio

Management new business

• Mid marketing new

business

“Non Power” Executed

• Retail, Wholesale

executed gas sales

• Load Response
• Energy Efficiency
• BGE Home
• Distributed Solar

“Non Power” New Business

• Retail, Wholesale

planned gas sales

• Load Response
• Energy Efficiency
• BGE Home
• Distributed Solar
• Portfolio

Management /

• rigination fuels

new business

• Proprietary

trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed Margins move from “Non power new business” to “Non power executed” over the course of the year

Gross margin linked to power production and sales Gross margin from

• ther business activities

(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region. (2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh. (3) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non power” executed category. 2013 EEI Conference

37

ExGen Disclosures

2013 EEI Conference

Gross Margin Category ($M) (1,2) 2013 2014 2015 2016 Open Gross Margin (including South, West & Canada hedged GM) (3) $5,600 $5,650 $5,800 $5,800 Mark to Market of Hedges (3,4) $1,700 $900 $450 $250 Power New Business / To Go $50 $500 $750 $750 Non-Power Margins Executed(5) $400 $200 $100 $100 Non-Power New Business / To Go(5) $200 $400 $500 $500 Tot

• tal

al Gross Margin $7,9 ,950 $7,6 ,650 $7,6 ,600 $7,4 ,400

(1) Gross margin rounded to nearest $50M. (2) Gross margin does not include revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and entities consolidated solely as a result of the application of FIN 46R. (3) Includes CENG Joint Venture. (4) Mark to Market of Hedges assumes mid-point of hedge percentages. (5) Any changes to new business estimates for our non-power business are presented as revenue less costs of sales. (6) Based on September 30, 2013 market conditions.

Reference Prices (6) 2013 2014 2015 2016 Henry Hub Natural Gas ($/MMbtu) $3.65 $3.86 $4.06 $4.17 Midwest: NiHub ATC prices ($/MWh) $31.18 $30.25 $30.47 $30.99 Mid-Atlantic: PJM-W ATC prices ($/MWh) $37.58 $37.19 $37.53 $38.13 ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$1.09 $6.30 $8.18 $7.13 New York: NY Zone A ($/MWh) $37.07 $35.54 $35.70 $36.07 New England: Mass Hub ATC Spark Spread($/MWh) ALQN Gas, 7.5HR, $0.50 VOM $3.70 $4.88 $3.69 $2.33

38

ExGen Disclosures

Generat eration ion and Hedges 2013 2014 2015 2016

• Exp. Gen (GWh) (1)

214,700 215,500 209,400 211,000 Midwest 97,200 96,900 96,400 97,400 Mid-Atlantic (2) 74,500 73,600 70,100 71,400 ERCOT 13,200 17,800 19,600 19,400 New York (2) 14,000 12,500 9,300 9,300 New England 15,800 14,700 14,000 13,500 % of Expected Generation Hedged (3) 97-100% 84-87% 48-51% 19-22% Midwest 97-100% 85-88% 47-50% 16-19% Mid-Atlantic (2) 97-100% 90-93% 56-59% 21-24% ERCOT 92-95% 81-84% 39-42% 31-34% New York (2) 98-101% 87-90% 54-57% 19-22% New England 95-98% 49-52% 22-25% 7-10% Effective Realized Energy Price ($/MWh) (4) Midwest $37.00 $33.50 $33.00 $34.00 Mid-Atlantic (2) $49.00 $45.00 $45.00 $49.00 ERCOT(5) $24.00 $11.00 $9.50 $6.50 New York (2) $32.00 $37.00 $42.50 $39.50 New England (5) $6.00 $3.50 $2.00 $5.50

(1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2013, 14 refueling outages in 2014 and 2015 and 12 refueling outages in 2016 at Exelon-operated nuclear plants, Salem and CENG. Expected generation assumes capacity factors of 94.1%, 93.7%, 93.3%, and 94.4% in 2013, 2014, 2015 and 2016 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2014, 2015 and 2016 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Includes CENG Joint Venture. (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. Uses expected value on options. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in

• margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load
• bligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark

spreads shown for ERCOT and New England. 2013 EEI Conference

39

ExGen Hedged Gross Margin Sensitivities

(1) Based on September 30, 2013 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various assumptions are also considered. (2) Sensitivities based on commodity exposure which includes open generation and all committed transactions. (3) Includes CENG Joint Venture.

Gross Margin Sensitivities (With Existing Hedges) (1, 2, 3) 2013 2014 2015 2016

Henry Hub Natural Gas ($/MMbtu) + $1/Mmbtu $10 $110 $370 $575

• $1/Mmbtu

$0 $(45) $(305) $(550) NiHub ATC Energy Price + $5/MWh $0 $65 $325 $450

• $5/MWh

$0 $(60) $(325) $(450) PJM-W ATC Energy Price + $5/MWh $0 $35 $175 $290

• $5/MWh

$0 $(35) $(170) $(280) NYPP Zone A ATC Energy Price + $5/MWh $0 $5 $20 $35

• $5/MWh

$0 $(10) $(20) $(35) Nuclear Capacity Factor +/- 1% +/- $10 +/- $40 +/- $45 +/- $45

2013 EEI Conference

40

Exelon Generation Hedged Gross Margin Upside/Risk

(1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2014, 2015 and 2016 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2013 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions.

5,500 6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 2016 2015 2014 2013 $9,300 $8,400 $7,950 $8,000

Approximate Gross Margin ($ million) (1,2)

$7,900 $7,300

2013 EEI Conference

$6,900 $5,900

Row Item Midwest Mid- Atlantic ERCOT New York New England South, West & Canada

(A) Start with fleet-wide open gross margin $5.65 billion (B) Expected Generation (TWh) 96.9 73.6 17.8 12.5 14.7 (C) Hedge % (assuming mid-point of range) 86.5% 91.5% 82.5% 88.5% 50.5% (D=B*C) Hedged Volume (TWh) 83.8 67.3 14.7 11.1 7.4 (E) Effective Realized Energy Price ($/MWh) $33.50 $45.00 $11.00 $37.00 $3.50 (F) Reference Price ($/MWh) $30.25 $37.19 $6.30 $35.54 $4.88 (G=E-F) Difference ($/MWh) $3.25 $7.81 $4.70 $1.46 $(1.38) (H=D*G) Mark-to-market value of hedges ($ million) (1) $275 million $525 million $70 million $15 million $(10) million (I=A+H) Hedged Gross Margin ($ million) $6,550 million (J) Power New Business / To Go ($ million) $500 million (K) Non-Power Margins Executed ($ million) $200 million (L) Non- Power New Business / To Go ($ million) $400 million

(N=I+J+K+L)

Total Gross Margin $7,650 million

41

Illustrative Example of Modeling Exelon Generation 2014 Gross Margin

(1) Mark-to-market rounded to the nearest $5 million. 2013 EEI Conference

42

Constellation Energy Nuclear Group (CENG) Background

As a result of Exelon’s equity interest in CENG, CENG gross margins and earnings are reflected in ExGen disclosures and other financial statements. The following is information related to PPA contracts between CENG and 3rd parties and the PPA between CENG and its equity parents.

Calvert 1&2 NMP 1 NMP 2 (1) Ginna(2)

Ownership Interest

Total Plant Capacity 1,756 MW 617 MW 1,279 MW 577 MW Ownership Split 100% CENG 100% CENG 82% CENG / 18% LIPA 100% CENG ExGen Ownership (50.01% of CENG) 878 MW 308 MW 524 MW 288 MW

PPA structure (% output)

CENG Legacy PPA with Utilities

• See footnote 1

90% < June 2014 0% > June 2014 CENG PPA with Parents 100% 100% 100% 10% < June 2014 100% > June 2014

(1) Nine Mile Point 2 (NMP) has a revenue sharing agreement (via a call option type contract) on 80% of the output. (2) Ginna Legacy PPA at $44/MWh; CENG PPA with parents (ExGen, EDF) at close to market prices and designed to maintain a monthly ratable profile for CENG.

CENG PPA with Parents 5 year contract extendable at end of each year for additional year - Market based pricing and monthly, rolling 3 year hedge profile (100%, 60%, 30%)

2012 2012 2013 2013 2014 2014 2015 2015 (% of uncommitted output) EDF Trading 15 15 15 N.A. ExGen 85 85 85 N.A.

2013 EEI Conference

43

Constellation Energy Nuclear Group (CENG) Background

ExGen Disclosures Forward Estimates

• ExGen forward disclosures reflect the gross position that

accrues to ExGen from ownership interest in CENG and PPA with CENG as of a certain date

• Open Gross Margin: Reflects proportionate share of

CENG revenues and fuel costs, market value of PPA less PPA costs paid by ExGen to CENG

• MtM of Hedges: Reflects MtM of any hedges placed by

ExGen for managing position arising from ownership interests or PPAs with CENG

• Expected Generation: Reflects proportionate ownership

in CENG and generation associated with PPA between CENG and ExGen.

• Hedge Percentage: Reflects hedges placed by ExGen to

hedge exposure arising from CENG position (owned or contracted)

• Effective Realized Energy Price: Reflects MtM and

hedges from CENG position (owned or contracted)

Financial Statements

(10-Q, 10-K, Earnings Release tables) Actuals

• ExGen actuals reflect equity method accounting

treatment for ownership interest in CENG and regular treatment for PPA between ExGen and CENG.

• RnF: Includes net PPA gross margin (revenues less

costs) between ExGen and CENG. CENG earnings or gross margin are not included, and are instead shown under “CENG equity earnings” on the income statement.

• Total Supply: Includes only the generation corresponding

to the PPA between ExGen and CENG.

• Average Margins ($/MWh): Includes only margins

corresponding to PPA between ExGen and CENG as well as any hedges placed by ExGen

2013 EEI Conference

Generation

Exelon Generation Fleet

A clean and diverse portfolio that is well positioned for environmental upside from EPA regulations

(1) Total owned generation capacity as of 9/30/2013. Nuclear capacity reflects EXC ownership of CENG and Salem. 45

National Scope

• Power generation assets in 20 states and

Canada

• Low-cost generation capacity provides

unparalleled leverage to rising commodity prices

Large and Diverse

• 35 GW of diverse generation(1)

− 19 GW of Nuclear − 10 GW of Gas − 2 GW of Hydro − 2 GW of Oil − 1 GW of Coal − 1 GW of Wind/Solar/Other

Clean

• One of nation’s cleanest fleets as

measured by CO2, SO2 and NOx intensity

• Less than 5% of generation capacity will

require capital expenditures to comply with Air Toxic rules

2013 EEI Conference

Executing on Generation Development and Growth Projects

Expanding the contracted renewable portfolio of Solar and Wind while adding incremental MWs to our existing nuclear fleet

46

Wind

• Six projects completed in

2012, added 404 MWs to the wind portfolio — All projects done under long-term PPAs with anticipated payback in approximately 10 years

• 45.6 MW wind farm in

Michigan to be built in 2014

Solar

• Antelope Valley Solar Ranch

Project One ― Large scale solar project that will be 230 MW once fully

• perational
• 128 MW currently online,

additional 54 MW by Fall 2013

• 48 MW by first half of 2014

― Initial investment fully recovered by 2015 ― 25-year PPA for entire output with Pacific Gas & Electric ― Cashflow and EPS accretive in 2013

Los Angeles

AVSR 1 Wildc ldcat Wind nd

Nuclear Uprates

• Peach Bottom Extended

Power Uprate — Adding 130 MW — Online dates of 65 MW in Q1 2015 and 65 MW in Q1 2016

2013 EEI Conference

Exelon Nuclear Fleet Overview (including CENG and Salem)

Plant Location Type/ Containment Water Body License Extension Status / License Expiration(1) Ownership Spent Fuel Storage/ Date to lose full core discharge capacity(2) Braidwood, IL (Units 1 and 2) PWR Concrete/Steel Lined Kankakee River Filed application in May 2013 (decision expected in 2015)/ 2026, 2027 100% Dry Cask Byron, IL (Units 1 and 2) PWR Concrete/Steel Lined Rock River Filed application in May 2013 (decision expected in 2015)/ 2024, 2026 100% Dry Cask Clinton, IL (Unit 1) BWR Concrete/Steel Lined / Mark III Clinton Lake 2026 100% Dry Cask (2016) Dresden, IL (Units 2 and 3) BWR Steel Vessel / Mark I Kankakee River Renewed / 2029, 2031 100% Dry Cask LaSalle, IL (Units 1 and 2) BWR Concrete/Steel Lined / Mark II Illinois River 2022, 2023 100% Dry Cask Quad Cities, IL (Units 1 and 2) BWR Steel Vessel / Mark I Mississippi River Renewed / 2032 75% Exelon, 25% Mid- American Holdings Dry Cask Calvert Cliffs, MD (Units 1and 2) PWR Concrete/Steel Lined Chesapeake Bay Renewed / 2034, 2036 100% CENG(4) Dry Cask R.E. Ginna, NY (Unit 1) PWR Concrete/Steel Lined Lake Ontario Renewed / 2029 100% CENG(4) Dry Cask Limerick, PA (Units 1 and 2) BWR Concrete/Steel Lined / Mark II Schuylkill River Filed application in June 2011 (decision expected in 2015) / 2024, 2029 100% Dry Cask Nine Mile Point, NY (Units 1 and 2) BWR Steel Vessel / Mark I Concrete/Steel Vessel/ Mark II Lake Ontario Renewed / 2029, 2046 100% CENG(4) / 82% CENG(4), 18% Long Island Power Authority Dry Cask Oyster Creek, NJ (Unit 1) BWR Steel Vessel / Mark I Barnegat Bay Renewed / 2029(3) 100% Dry Cask Peach Bottom, PA (Units 2 and 3) BWR Steel Vessel / Mark I Susquehanna River Renewed / 2033, 2034 50% Exelon, 50% PSEG Dry Cask TMI, PA (Unit 1) PWR Concrete/Steel Lined Susquehanna River Renewed / 2034 100% 2023 Salem, NJ (Units 1 and 2) PWR Concrete/Steel Lined Delaware River Renewed / 2036, 2040 42.6% Exelon, 57.4% PSEG Dry Cask

(1) Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review. (2) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools. (3) On December 8, 2010, Exelon announced that it will permanently cease generation operations at Oyster Creek by December 31, 2019. Oyster Creek’s current NRC license expires in 2029. (4) Exelon Generation has a 50.01% ownership interest in CENG (Constellation Energy Nuclear Group, LLC). Electricite de France SA (EDF) has a 49.99% ownership interest in CENG.

Midwest Mid-Atlantic

47 2013 EEI Conference

10.00 12.00 14.00 16.00 18.00 20.00 22.00 24.00 26.00 28.00 30.00 32.00

Operat ator

• r

Range 5-Year Average 31% 36% 14% 14%

48 1,208 1,169 1,104

(1) Exelon fleet averages exclude Salem and CENG (2) Source: 2012 Electric Utility Cost Group (EUCG) survey. Includes Fuel Cost plus Direct O&M divided by net generation. (3) Source: Platts Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy).

Nuclear Production Cost ($/MWh)(2) Capacity Factor (%)(3)

Nuclear Production Cost (‘08-’12)

EXC

70.0 75.0 80.0 85.0 90.0 95.0 100.0

Operat ator

• r

Range 5-Year Average

Nuclear Capacity Factor (‘08-’12)

EXC

World Class Nuclear Operator(1)

Among major nuclear plant fleet operators, Exelon is consistently one of the lowest-cost and most efficient producers of electricity in the nation

2013 EEI Conference

10 15 20 25 30 35 40 45 50 55 60 65 70

Operat ator

• r

Range 5-Year Average

Nuclear Output and Refueling Outages

Fleet Average Refueling Outage Duration (Days)(1) 31% 36% 14% 14% Nuclear Output(1)

‘000 GWH (1) Net nuclear generation data at ownership excluding Salem and CENG. 2016 includes Clinton Refueling Only outage of shortened duration. 49 1,208 1,169 1,104

Nuclear Refueling Cycle

• All Exelon owned units on a 24 month cycle

except for Braidwood U1/U2, Byron U1/U2 and Salem U1/U2, which are on 18 month cycles

• Starting in 2015 Clinton is on annual cycles

7 7.5 8 8.5 9 9.5 10 10.5 125 127 129 131 133 135 137 139 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Actual Target # of Outages

2013 Refueling Outage Impact

• 10 planned refueling outages, including 1 at

Salem

• Exelon completed 4 refueling outages in the

Spring with an average duration of 24 days

• Salem completed 1 refueling outage in the

Spring

• 5 Exelon planned Fall refueling outages

(Braidwood 1, Peach Bottom 3, Clinton, Three Mile Island and Dresden 2)

2014 Refueling Outage Impact

• 11 planned refueling outages, including 2 at

Salem

• 5 Exelon planned Spring refueling outages and

4 planned Fall refueling outages

• 1 Salem planned Spring refueling outage and 1

planned Fall refueling outage

Average Refueling Duration (‘08-’12)

(1) Exelon fleet averages exclude Salem and CENG.

EXC

2013 EEI Conference

Nuclear Fuel Costs(1)

Projected Exelon (100%) Uranium Demand Components of Fuel Expense in 2013

2013 – 2016: 100% hedged in volume 2017: ~80% hedged in volume 2018: ~50% hedged in volume

2 1 11 10 9 8 7 6 5 4 3 2018E 2017E 2016E 2015E 2014E 2013 M lbs

Enrichment

30%

Tax/Interest

2%

Conversion

3%

Uranium

38%

Nuclear Waste

13%

Fabrication

14% Projected Exelon Average Uranium Cost vs. Mar

(1) All charts exclude Salem and CENG. (2) At ownership, excluding Salem and CENG. Excludes costs reimbursed under the settlement agreement with the DOE. 50

Projected Total Nuclear Fuel Spend(2)

200 400 600 800 1,000 1,200 2018E 1125 2017E 1100 2016E 1100 2015E 1050 2014E 1025 2013E 1000 Nuclear Fuel Capex Nuclear Fuel Expense (Amortization + Spent Fuel) $ $ Millions 2013 EEI Conference

Constellation Energy Nuclear Group (CENG) Operating Services Agreement

51

• Agreemen

ements ts signed d bet etween een Exelon n and EDF, with expected ed close e in 2014 (first st qua quarter

• r

r earl rly second nd quarter)

• Nuclea

ear Operati ting g services ces agreemen ent

• Integrate CENG and their 3 plants into Exelon Nuclear with transfer of operating licenses
• Utilize Exelon Nuclear Management Model to improve plant performance
• Leverage scale and obtain cost efficiencies of running a larger, integrated fleet
• Expect cost synergies of $50-$70M at 100% ownership
• Loan to CENG and distributions

ibutions to EDF/Ex Exel elon

• n Generati

tion

• n
• Exelon Generation $400M loan to CENG at 5.25% annual interest rate
• CENG $400M special distribution to EDF
• Exelon Generation to receive preferred distributions from CENG’s available cash flows until loan is fully

repaid

• Exelon Generation also to receive aggregate distributions of $400M plus a return of 8.5% per annum from

the date of the special dividend

• Option

ion provision ion for EDF to sell its 49.99% interest st in CENG G to Exelon n Generat ation ion

• Exercisable from January 2016 to June 2022, priced at fair market value
• Indemn

emnify ify EDF in the event t of a future e nuclear ar inciden ent t (as define ned d in the Price Anders rson n Act) in connect ction

• n with the CENG nuclear

r plants s or t r their r opera rations tions

• Given Exelon’s size and past performance, no material impact to premiums

Leverages Exelon’s best-in-class operations, scale and low-cost fleet to add value

2013 EEI Conference